Subsea pump and system and methods for control

ABSTRACT

A subsea or downhole pump includes an inlet and an outlet. A flow of a multiphase fluid entering the inlet can have a variation in a gas volume fraction (GVF). The subsea or downhole pump includes or is operatively coupled to control devices which provide for a control as the GVF varies. The control devices include a first transmitter for an electric pump current, a second transmitter for at least one of a pump speed, a pump frequency, and a pump voltage, and a controller. The controller reduces a speed of the subsea or downhole pump when a measured pump current decreases, and increases the speed of the subsea or downhole pump when the measured pump current increases.

CROSS REFERENCE TO PRIOR APPLICATIONS

This application is a U.S. National Phase application under 35 U.S.C. § 371 of International Application No. PCT/NO2016/050152, filed on Jul. 5, 2016 and which claims benefit to U.S. Provisional Patent Application No. 62/190,831, filed on Jul. 10, 2015, and to Norwegian Patent Application No. 20150973, filed on Jul. 27, 2015. The International Application was published in English on Jan. 19, 2017 as WO 2017/010891 A1 under PCT Article 21(2).

FIELD

The present invention relates to subsea pumping of a multiphase fluid. The present invention more specifically relates to a subsea or downhole pump and a subsea pump system comprising a subsea pump and a flow conditioning system operatively coupled to the subsea pump, and methods for control thereof.

BACKGROUND

Most subsea pumps are driven by a variable speed drive (a “VSD”), which is also termed a variable frequency drive (a “VFD”). A variable speed drive provides for a stepless variable control of a pump speed. An adjustable speed drive (an “ASD”) provides for a stepwise control and can alternatively be used to drive a subsea pump. The term VSD as used herein covers VSDs, VFDs and ASDs. A subsea or topsides RotoConverter, a motor generator set, is a feasible option as a subsea pump drive, particularly for high power subsea pumps deployed with long subsea step outs.

A VSD located topsides or onshore is the most used device to drive a subsea pump. An increase in frequency and speed is typically accompanied by an increase in torque, thereby allowing the subsea pump to operate at higher power. The relationship between torque, power and speed can, however, be complex for various reasons, for example, that the fraction of the applied power that contributes to hydraulic (pumping) work varies. The gas/liquid mixture and density are important factors that contribute to change in pumping performance.

Subsea pumps have a difficult location and restricted access for maintenance; reliability is therefore vital. Any improvement in the reliability of subsea pumps is welcome.

It is well known that operating pumps at feasible operating conditions will prolong service life. The optimal condition is often termed the “sweet spot”, which is often achievable for a steady state operating situation.

Control is complex for subsea pumps receiving multiphase flow of variable gas volume fraction. The pump curve and therefore optimal setpoint for operation changes according to the gas fraction. Comprehensive subsea instrumentation to control the pump operation and robust pump design to allow the pump to operate for longer periods under harsh operating conditions are typical measures to provide reliability. Subsea multiphase flow meters and level sensors in pipes and equipment upstream to the pump are typical examples of instrumentation needed to control a subsea pump. Control devices and fluid conditioning devices, such as recirculation lines, valves, chokes, mixers, and related instrumentation, are used for control of varying gas volume fraction (“GVF”) of a multiphase flow to be pumped.

U.S. Pat. No. 5,254,292, GB 2 215 408, U.S. Pat. No. 5,393,202, US 2011/0155385, WO 2015/011369, U.S. Pat. No. 8,857,519 B2, the OTC paper OTC16477 “An efficient Wellstream Booster Solution for Deep and Ultradeep Water Oil Fields”, May 3-6, 2004, the document SPE 146784 of February 2012, the document “Proceedings of the thirteenth international pump user symposium, page 159, and the textbook “Pumping of Gas-Liquid Mixtures, page 890, “Centrifugal Pumps” by Johan Friedrich Gülich, 3^(rd) edition 2014, provide background art relevant for the present invention.

The above mentioned publications contain no teaching as to how the speed of a subsea or downhole pump should be controlled as the gas volume fraction of a multiphase flow enters the pump without depending on multiphase metering, level metering, or some other subsea instrumentation.

SUMMARY

An aspect of the present invention is to provide improved reliability to subsea pumps, downhole pumps, and a subsea pump system and related methods for the control thereof.

In an embodiment, the present invention provides a subsea or downhole pump which includes an inlet and an outlet. A flow of a multiphase fluid entering the inlet can have a variation in a gas volume fraction (GVF). The subsea or downhole pump comprises or is operatively coupled to control devices which provide for a control as the GVF varies. The control devices consist of a first transmitter for an electric pump current, a second transmitter for at least one of a pump speed, a pump frequency, and a pump voltage, and a controller. The controller reduces a speed of the subsea or downhole pump when a measured pump current decreases, and increases the speed of the subsea or downhole pump when the measured pump current increases.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention is described in greater detail below on the basis of embodiments and of the drawings in which:

FIG. 1 shows a typical embodiment of a subsea pump of the present invention; and

FIG. 2 shows a pump system of the present invention.

DETAILED DESCRIPTION

The present invention provides a subsea or downhole pump comprising an inlet and an outlet, where a multiphase fluid flow entering the inlet can have a variation in the gas volume fraction (GVF) of the fluid, the subsea or downhole pump being distinctive in that it includes or is operatively coupled to devices for normal pump control as the GVF varies, the devices consisting of:

-   -   a transmitter for electric pump current;     -   a transmitter for at least one of: pump speed, pump frequency,         or pump voltage; and     -   a controller acting to reduce the pump speed when the measured         pump current decreases and to increase the pump speed when the         measured pump current increases.

The devices for measuring the parameters electric current and measuring or using a set pump speed or frequency or pump voltage can, for example, be integrated into or coupled for real-time measurements at a topsides or onshore variable speed drive, thereby eliminating the requirement or use of subsea or downhole instrumentation. The devices can, for example, consist of a transmitter for electric pump current and a transmitter for pump speed.

In an embodiment, the pump can, for example, be a subsea pump and a flow conditioning unit arranged upstream to the pump to dampen the variation of a gas volume fraction (GVF) and to reduce gas bubble sizes in a multiphase flow entering the inlet to the fluid conditioning unit to an acceptable level for delivery of a multiphase fluid through an outlet of the fluid conditioning unit to the downstream subsea pump, and a liquid collecting unit arranged downstream to the pump, with a liquid recirculation line from the liquid collecting unit to upstream of the pump, providing liquid for decreasing the GVF to an acceptable level for the pump in situations where the GVF is excessive. In addition or as an alternative for allowing a higher GVF, a line is coupled to the flow conditioning unit, for example, a pipe of an umbilical arranged to a topsides position, to export excessive gas or to import liquid in a situation of excessive GVF of the multiphase fluid to be pumped.

In an embodiment, the pump can, for example, be an ESP (an electrical submersible pump) arranged in a subsea flowline jumper.

The present invention also provides a method for control of a subsea or downhole pump according to the present invention, the method having the steps of: measuring or transmitting parameters in the group of parameters consisting of: electric pump current and at least one of pump speed or frequency and pump voltage, and reducing the pump speed when the measured pump current decreases, and increasing the pump speed when the measured pump current increases. The parameters can, for example, consist of electric current and pump speed, which are measured in real-time at a topsides variable speed drive.

The present invention also provides a subsea pump system comprising a subsea pump with an inlet and an outlet, where a multiphase fluid flow entering the system can have a higher gas volume fraction (GVF), a larger variation in the GVF, or larger gas bubbles, than acceptable for efficient and reliable operation of the subsea pump. The subsea pump system further comprises:

-   -   a flow conditioning unit arranged upstream to the subsea pump;     -   a liquid collecting unit arranged downstream to the subsea pump;         and     -   a liquid recirculation line arranged from the liquid collecting         unit to upstream of the subsea pump,     -   wherein,     -   the flow conditioning unit reduces the variation in GVF, mixes         gas and liquid and reduces the size of gas bubbles in a         multiphase flow entering the inlet to the flow conditioning         unit, and recirculation of liquid from the liquid containment         unit reduces the GVF of the flow entering an inlet of the subsea         pump, so that the subsea pump can operate within an operational         window with efficient and reliable operation, and     -   the subsea pump includes or is operatively coupled to devices         for normal pump control as the GVF of the pump inlet flow         varies, the devices consisting of:     -   a transmitter for electric pump current,     -   a transmitter for at least one of: pump speed, pump frequency or         pump voltage, and     -   a controller acting to reduce the pump speed when the measured         pump current decreases and to increase the pump speed when the         measured pump current increases.

For the subsea pump system according to the present invention:

-   -   the flow conditioning unit can, for example, comprise an inlet,         a volume, and an outlet with a perforated outlet pipe extending         upwards into the volume;     -   the liquid collecting unit can, for example, comprise an inlet,         a volume, and an outlet with an outlet pipe extending upwards         into the volume, the outlet pipe being perforated only in an         upper part of the volume; and     -   the liquid recirculation line being arranged, for example, from         a lower liquid filled part of the volume of the liquid         collecting unit to the flow conditioning unit.

For the subsea pump system according to the present invention, the devices for measuring the parameters electric current and at least one of pump speed or frequency and voltage, for example, electric current and pump speed, can, for example, be integrated into or be coupled for real-time measurements at a topsides or onshore variable speed drive, thereby eliminating the requirement or use of subsea instrumentation.

In an embodiment, the subsea pump system according to the present invention can, for example, comprise a line coupled to the flow conditioning unit, for example, a pipe of an umbilical arranged to a topsides position, for export of excessive gas or import of liquid in a situation of excessive GVF of the multiphase fluid to be pumped. The controller can also activate a topsides valve in a line going from the subsea conditioning unit through the umbilical to the topsides separator to vent excessive gas. The controller can thereby alter the gas-to-liquid ratio going to the pump in a favorable way to increase pump efficiency. If arranged differently or as an alternative, a topside located valve and pump can be activated by the same controller to feed additional liquid to the conditioning unit to obtain better operational pumping conditions.

In an embodiment, the subsea pump of the pump system of the present invention can, for example, be an ESP (an electrical submersible pump) arranged in a flow line jumper.

The present invention also provides a method for control of the subsea pump system of the present invention, comprising the steps of: measuring or transmitting parameters in the group of parameters consisting of: electric pump current and at least one of pump speed or frequency and pump voltage, and reducing the pump speed when the measured pump current decreases, and increasing the pump speed when the measured pump current increases. The parameters more consistently consist of electric current and pump speed measured in real-time at a topsides variable speed drive.

The embodiments of the present invention, that is the pumps of the present invention and the pump system of the present invention, and associated respective methods, have in common that the devices for normal pump control as the GVF varies, consist of: a transmitter for electric pump current and a transmitter for at least one of pump speed or frequency and pump voltage, and a controller acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases.

The electric pump current is measured. The at least one additional parameter: pump speed or frequency and pump voltage, is measured or transmitted as a set. Speed and frequency are synonyms in this context since skilled persons know that a VSD frequency and the pump speed are directly related. Pump voltage and speed/frequency are directly related in a pump speed range of from zero up to a base load; pump voltage can therefore be measured or transmitted as the parameter additional to pump electric current for normal control of the pump as the GVF varies.

The skilled person will recognize that the present invention has two main embodiments: one with a fluid conditioning system, that is the pump system of the present invention and related method; and one without the requirement of a fluid conditioning system, that is the subsea pump or downhole pump of the present invention and related method.

The pump system of the present invention is feasible when the GVF or variation thereof, or occurrence of large gas bubbles or other limiting factors, of a multiphase flow is higher or larger than the pump per se can handle effectively and reliably, since the fluid conditioning system dampens the variation in GVF, mixes the phases, break up large gas bubbles and recirculates liquid. For an ESP, the limit is typical about 35% GVF, meaning that the pump system of the present invention is feasible at a higher GVF. For a liquid subsea pump, efficiency and reliability can drop too much when the GVF exceeds 10%, for a state of the art multiphase pump, efficiency and reliability can drop too much when the GVF exceeds 80%. The exact limit for acceptable maximum GVF will, however, depend on other factors and economic considerations as well, hence the reference to efficiency. Other factors are pressure, since higher pressure results in a higher allowable GVF since the density of the gas phase is increased and conversely lower pressure reduces the allowable GVF, and the density of the liquid phase components, since a low density liquid will separate out more gas at reduced pressure, and viscosity. Large variations in the gas fraction entering a centrifugal pump can be very detrimental to the pump's function and service life. Even centrifugal pumps that are specifically designed to handle high gas fractions, such as the helico-axial pump described in U.S. Pat. No. 5,375,976, will have a substantial efficiency drop with high gas fractions. While standard centrifugal pumps with a radial impeller will gas-lock (zero efficiency) at 10% gas, the helico-axial pumps will maintain a pumping efficiency of approximately 30% with an 80% gas fraction. At a fixed speed, the ability to generate pressure will also drop significantly with increasing gas fractions. All centrifugal pumps including its drivetrain will be exposed to high vibrations and rapid load variations if the gas fraction rapidly changes and with a large amplitude. In order to obtain reliability and long service life, it is therefore important that rapid variations of gas fractions be avoided. Since the pressure generation is dependent upon the average gas fraction, it is also important that such variations are slow enough to allow for compensation by pump speed adjustment. Many factors are in practice related, and each well or well system will have to be considered specifically. Turpin curves or similar curves can be feasible in this context. The terminology “normal pump control as the GVF of the pump inlet flow varies” refers to the expected flow conditions expected for 100% or in substance 100% of the time of operation. Collapse of wells or upstream equipment can give unexpected flow conditions, which may result in shut down or may require different solutions to handle. If the expected GVF is too high, or the variation of GVF is too high for the actual subsea pump, the subsea pump system of the invention will be feasible.

The specified control devices are the only devices required and used for normal control of the pump or pump system as the GVF of the inlet flow to the pump varies. The phrase “a controller acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases” means that the pump speed change is sufficient to reverse an increasing GVF in the inlet flow and reverse a decreasing GVF in the inlet flow, achieving a regulation at or around a favorable GVF of the inlet flow. The control must act faster than the variation in GVF of the inlet flow, and should, for example, adjust the pump speed setpoint to a changed GVF when the speed changes are not symmetrical about increase and decrease of the speed.

Additional instrumentation is superfluous for normal operation with respect to varying GVF of the inlet flow to the pump of the present invention. Any additional instrumentation, if present, can be for redundancy and other purposes. The pump is without any subsea instrumentation for normal control thereof if the pump is driven by a topside or onshore-located drive, such as a topsides VSD or a topsides RotoConverter, since all input parameters can be measured or taken from the topsides or onshore drive. This also means that the pump is without, or does not need for normal operation, any recirculation or bypass lines, control valves, or chokes or mixers for controlling the recirculation or bypass flow through the recirculation line or a bypass line, and related subsea instrumentation. Multiphase meters or level sensors are not required for control of the pump of the present invention, thereby providing savings of USD 500,000 or higher and increasing reliability.

The algorithms applied may sufficiently estimate gas volume fraction at the pump input, thereby allowing selection of the appropriate pump curve for the fluid density. Control of the pump is driven by a subsea, topside, or onshore-located drive, such as a VSD, or RotoConverter. All input parameters to infer the liquid level of the fluid conditioning unit can be measured or taken from the electrical system at the drive, for example, topsides, or at the pump motor input.

The term “subsea pump” means a pump located on or at the seabed. The subsea pump can be a typical seabed located subsea centrifugal pump or an electrical submersible pump arranged in a flow line jumper, such as POWERJump™ as available from the Subsea Production Alliance. The term “downhole pump” means an ESP (an electrical submersible pump) which is a long slim pump normally arranged in a wellbore. The pump and pump system of the present invention can, for example, be or comprise centrifugal pumps, respectively. The controller and the drive of the pump and pump system of the present invention, respectively, can, for example, be arranged topsides or onshore.

Each of the subsea pump of the present invention, the subsea pump system of the present invention, and the methods of the present invention, can include any feature or step herein described or illustrated, in any operative combination, each such operative combination being an embodiment of the present invention.

As mentioned, a VSD typically has a given output voltage for a given frequency, at least for a given operation window, such as from very low speed up to a base load speed. Voltage can accordingly be measured or used as an input parameter, together with current, instead of speed/frequency. Because the applicant has verified that a direct correlation between motor current, speed, and GVF exists, a simple control algorithm can be used. The deviation from a reference current at a set or measured speed or voltage for a reference GVF can be used as the proportional input to a control algorithm. Alternatively, a look up table established during commissioning can be used for the control. The GVF of the pump inlet flow or a fluid conditioning unit liquid level can alternatively be inferred based on the measured pump current for a set or measured speed/frequency or voltage, the pump speed then being adjusted according to the inferred GVF or liquid level.

For a RotoConverter, that is a motor generator set, a look up table established during commissioning, giving the relation between the GVF and the measured parameters, can be used for control. It is likely, however, that a similar or identical relationship between the GVF and the measured parameters also exists for a RotoConverter, allowing a control algorithm to be developed. The RotoConverter can, for example, be a passive machine without any active subsea control or instrumentation for normal operation, allowing for merely topsides control from a VSD.

Even though merely current and speed or voltage are required for operation of the pump or pumps system as the GVF varies, the pump and pump system and upstream and downstream equipment may, for example, comprise sensors of various kinds which measure various parameters. These additional data can be used to optimize the control according to the methods of the present invention. The data can also be used to optimize operation and maintenance, for example, by finding patterns for sweet spot operation or early warning for wear or failure.

An embodiment of the present invention is described below under reference to the drawings.

A subsea pump 5 with motor 4 is driven by a topsides variable speed drive VSD 2, as illustrated in FIG. 1. A topsides controller 1 is operatively arranged to the VSD. A flow conditioning unit 3, arranged upstream to the pump 5, receives a multiphase flow through an inlet/connection line 7. An outlet 6 from the fluid conditioning unit 3 includes a perforated pipe section extending up above a liquid level in the flow conditioning unit 3, providing an average mix of gas and liquid to the pump inlet. When the liquid level in the flow conditioning unit 3 rises, more liquid is mixed into the flow from the flow conditioning unit 3 to the pump 5, resulting in a higher measured current. The control system 1 then increases the pump speed, resulting in a decreasing liquid level in the flow conditioning unit 3. When the liquid level in the flow conditioning unit 3 decreases below a chosen setpoint, more gas will be delivered to the pump 5, the control system 1 then decreases the pump speed. Accordingly, a in substance fixed GVF to the pump can be achieved, as well as a in substance fixed liquid level in the flow conditioning unit, in the illustrated example, a fluid retaining mixer tank. The devices required for normal pump control are as follows: a transmitter 28 for electric pump current; and a transmitter 29 for at least one of: pump speed, pump frequency or pump voltage; and a controller 30 acting to reduce the pump speed when the measured pump current decreases and to increase the pump speed when the measured pump current increases. These devices are only illustrated on FIG. 1 and are omitted in FIG. 2 for clarity.

FIG. 2 illustrates a pump system of the present invention. In addition to the pump 5, a fluid conditioning system is arranged to the pump 5 to dampen the variation in the GVF, decrease the GVF in the fluid entering the pump by retaining liquid, and recirculating liquid from a liquid collecting unit downstream of the pump 5. A flow conditioning unit (FCU) 3 is arranged upstream of the pump 5, a perforated outlet pipe extending upwards into a volume of the FCU 3 acting to mix the phases according to the liquid-gas level in the FCU 3. A liquid collecting unit (LCU) 10 arranged downstream of the pump 5 retains liquid for recirculating liquid to the pump inlet, for more effective pump operation. The LCU 10 comprises an inlet, a volume, and an outlet with an outlet pipe extending upwards into the volume, the outlet pipe being perforated only in an upper part of the volume to provide a liquid filled lower part of the volume of the LCU 10. A liquid recirculation line 11 is arranged from the lower liquid filled part of the volume of the LCU 10 to the FCU 3. Line 14 allows the supply of liquid (i.e., chemicals) from a topsides chemical injection unit or a hydraulic power unit to the pump system. Line 26 allows the draining of gas from the FCU 3 or the addition of fluid to the FCU 3 (as is explained below) and is controlled by a topsides valve 27. Lines 14, 26 can, for example, be pipes in an umbilical. Check valves 9 and 15 provide for a correct direction of flow. Valve 12 in liquid recirculation line 11 conveniently chokes down the recirculated liquid pressure.

More specifically, hydrocarbon flow from a subsea well 20 is routed through a subsea valve-stack (Christmas-tree) 21 and a flow-line jumper 22 to the subsea pump system 23. The inlet/connection line 7 to the boosting system is typically performed an ROV operated connectors 17 at a subsea template 19. The pressurized flow leaving the subsea pump system 23 is connected in a similar fashion via a connector 18, arranged on a subsea template 19 through a flow-line/riser arrangement 24 to a topsides receiver separator 25. The receiving separator 25 can be arranged on a platform or floating production vessel or another host facility. Several connections and communication lines from topside to the subsea pump system are typically bundled into an umbilical. This might contain the power lines 16 transmitting the variable frequency electric power to the pump motor 4. It further typically may contain one or more chemical injection lines 14 to handle flow assurance related issues. Chemical additives to eliminate the formation of hydrate, scale deposits, wax or asphaltenes are pressurized in a topsides chemical injection unit 13, routed through one or more lines 14 in the umbilical to a suitable injection point, for example at check valve 15, at the subsea pump system. Electric communication lines and/or fiber optic lines (not shown in FIG. 2) might also be included in the umbilical for data transfer. Line 26 can also be connected with the fluid conditioning unit 3 and the topside separator 25. The function line 26 will be described below.

The subsea pump system, also termed the boosting system, will typically be equipped with some additional components to enhance the function in the presence of high gas fractions and gas/liquid slugging. With reference to FIGS. 1 and 2, these components are described below while their function will be further elaborated later.

The incoming gas/liquid mixture via inlet/connection line 7 enters the fluid conditioning unit 3 FCU upstream the pump intake. The function of the FCU 3 is to buffer the liquid phase and in a controlled way re-mix the gas and liquid at the outlet. This is done to provide a homogenous mixture of gas and liquid entering into the pump 5 in order to obtain stable and good pump performance. The FCU 3 has a volume retaining gas and liquid, the perforated outlet pipe mixes the liquid based on how a liquid-gas level in the volume and how the perforations are arranged.

Conditioned fluid 6 enters the pump 5 driven by the (electrical) motor 4. The output flow 8 from the pump 5 is fed through check-valve 9 to prevent a backflow and into LCU 10. LCU 10 has the function of separating the gas and liquid and to retain or collect/store some of the liquid. The outlet from LCU 10 is arranged so that all the gas goes to the outlet stream together with some of the liquid. As some solids particles might be contained with the well flow, these particles are separated to the bottom of the LCU 10 and also routed to the outlet flow. Part of the remaining liquid in the LCU 10 is routed through a pressure reduction valve/choke 12 back to the FCU 3 in a separate liquid recirculation line 11.

An important feature in order to obtain stable operation of a pump of the kind described herein is to retain as much or at least sufficient incoming liquid in the recirculation system as possible. More specifically, liquid should be retained and recycled in order to achieve a GVF of less than 60% for the pump in order to avoid excessive heating and wear, when the pump is an ESP. Such liquid is mixed with the incoming gas-liquid flow and will reduce the gas-to-liquid fraction going to the pump. The liquid collecting unit at the pump outlet and recirculation of liquid from this tank to the inlet conditioning-mixer unit is therefore important.

A typical well fluid mixture consists of multi-components of various densities. When the lighter components in such a hydrocarbon mixture is depressurized across the choke (12 in FIG. 2), it is likely that they will flash back into gas when reaching the pump inlet. Such gas will not contribute to lower the gas-to-liquid fraction going to the pump. It is therefore important to design the liquid collection unit so that the heaviest liquid components are separated to be recirculated. The heaviest components coming with the well flow will be solids particles. Re-routing such particles via the recirculation system to the pump inlet is not favorable as it will create wear both on the choke and on the pump internals. The liquid collection unit is therefore constructed so that solids will be drained from the tank together with the gas and some liquid, for example, the lightest components. The outlet pipe from the LCU therefore comprises some perforations at the lowest level in the volume of the LCU, where solids will accumulate, in addition to perforations where gas and the lightest liquids will accumulate, towards the top of the volume.

Additional measures that can be used in order to alter the gas fraction going to the pump 5 includes using the additional line (26, FIG. 2) going from the FCU 3 to the topside separator 25. If the gas fraction in the FCU 3 is too high, line 26 can be used to drain gas into the topsides separator 25. Line 26 can alternatively be used to inject liquid from topsides to the FCU 3 and thereby reduce the gas fraction being fed to the pump 5. The use of line 26 can be controlled via valves located topsides.

The simplicity of the pump, pump system and methods of the present invention provides increased reliability. Each component of a pump or pump system represents a source of failure, reducing the number of components therefore improves reliability. Removing any need for control devices subsea or downhole further improves reliability. State of the art subsea pumps and downhole pumps, and subsea pump systems, require more comprehensive instrumentation, recirculation arrangements and other control devices, arranged subsea, for control of the operation as the GVF of an inlet multiphase flow varies.

The present invention is not limited to embodiments described herein; reference should be had to the appended claims. 

What is claimed is: 1-14. (canceled)
 15. A subsea or downhole pump comprising: an inlet; an outlet, wherein, a flow of a multiphase fluid entering the inlet can have a variation in a gas volume fraction (GVF), and the subsea or downhole pump comprises or is operatively coupled to control devices which provide for a control as the GVF varies, the control devices consisting of: a first transmitter for an electric pump current, a second transmitter for at least one of a pump speed, a pump frequency, and a pump voltage, and a controller which reduces a speed of the subsea or downhole pump when a measured pump current decreases, and which increases the speed of the subsea or downhole pump when the measured pump current increases.
 16. The subsea or downhole pump as recited in claim 15, wherein the first transmitter and the second transmitter are integrated into or coupled for a real-time measurement at a topsides variable speed drive or at an onshore variable speed drive so as to eliminate a subsea instrumentation or a downhole instrumentation.
 17. The subsea or downhole pump as recited in claim 15, wherein the control devices consist of: the first transmitter, and the second transmitter for the pump speed.
 18. The subsea or downhole pump as recited in claim 15, wherein, the subsea or downhole pump is a subsea pump, a flow conditioning unit comprising an inlet and an outlet is arranged upstream of the subsea pump, the flow conditioning unit being configured to dampen a variation of the GVF and to reduce a gas bubble size in the multiphase flow entering the inlet of the fluid conditioning unit to allow for a delivery of the multiphase fluid through the outlet of the fluid conditioning unit to the subsea pump, a liquid collecting unit is arranged downstream of the subsea pump, and a liquid recirculation line connects the liquid collecting unit to an area which is upstream of the subsea pump, the liquid recirculation line being configured to provide a liquid to decrease the GVF to an acceptable operating level of the subsea pump where the GVF is too high.
 19. The subsea or downhole pump as recited in claim 15, wherein the subsea or downhole pump is an electrical submersible pump (ESP) arranged in a subsea flowline jumper.
 20. A method for controlling the subsea pump or downhole pump as recited in claim 15, the method comprising: measuring or transmitting parameters selected from the group of parameters consisting of: the electric pump current, and at least one of the pump speed, the pump frequency, or the pump voltage; reducing the speed of the subsea or downhole pump when the electric pump current measured or transmitted decreases; and increasing the speed of the subsea or downhole pump when the electric pump current measured or transmitted increases.
 21. The method as recited in claim 20, wherein the parameters consist of the electric pump current and the pump speed which are measured or transmitted in real-time at a topsides variable speed drive.
 22. A subsea pump system comprising: a subsea pump comprising, an inlet, an outlet, wherein, a flow of a multiphase fluid entering the inlet can have a higher gas volume fraction (GVF), a larger variation in the GVF, or larger gas bubbles, than is acceptable for an efficient and reliable operation of the subsea pump; a flow conditioning unit comprising an inlet, the flow condition unit being arranged upstream of the subsea pump; a liquid collecting unit arranged downstream of the subsea pump; and a liquid recirculation line arranged to connect the liquid collecting unit with an area which is upstream of the subsea pump, wherein, the flow conditioning unit is configured, to reduce a variation in the GVF, to mix a gas and a liquid, and to reduce a size of gas bubbles in the multiphase flow entering the inlet of the flow conditioning unit, and to recirculate a liquid from the liquid collection unit so as to reduce the GVF of a flow entering the inlet of the subsea pump so that the subsea pump can operate within an operational window which provides for the efficient and reliable operation of the subsea pump, and the subsea pump comprises or is operatively coupled to control devices which provide for a control as the GVF at the inlet of the subsea pump varies, the control devices consisting of: a first transmitter for an electric pump current, a second transmitter for at least one of a pump speed, a pump frequency, and a pump voltage, and a controller which reduces a speed of the subsea pump when a measured pump current decreases, and which increases the pump speed of the subsea pump when the measured pump current increases.
 23. The subsea pump system as recited in claim 22, wherein, the flow conditioning unit further comprises a volume and an outlet which comprises a perforated outlet pipe which extends upwards into the volume, the liquid collecting unit comprises an inlet, a volume, and an outlet which comprises an outlet pipe which extends upwards into the volume, the outlet pipe comprising perforations only in an upper part of the volume, and the liquid recirculation line is arranged to connect a lower liquid filled part of the volume of the liquid collecting unit with the flow conditioning unit.
 24. The subsea pump system as recited in claim 22, wherein the first transmitter and the second transmitter are integrated into or coupled for a real-time measurement at a topsides variable speed drive or at an onshore variable speed drive so as to eliminate a subsea instrumentation or a downhole instrumentation.
 25. The subsea pump system as recited in claim 22, further comprising: a line coupled to the flow conditioning unit, the line being configured to export a gas or to import a liquid when an excessive GVF of the multiphase fluid to be pumped exists.
 26. The subsea pump system as recited in claim 22, wherein the subsea pump is an electrical submersible pump (ESP) arranged in a flow line jumper.
 27. A method for controlling the subsea pump system as recited in claim 22, the method comprising: measuring or transmitting parameters selected from the group of parameters consisting of: the electric pump current, and at least one of the pump speed, the pump frequency, or the pump voltage; reducing the speed of the subsea pump when the electric pump current measured or transmitted decreases; and increasing the speed of the subsea pump when the electric pump current measured or transmitted increases.
 28. The method as recited in claim 27, whereby the parameters consist of the electric current and the pump speed measured in real-time at a topsides variable speed drive. 